Legislature(2001 - 2002)
11/07/2001 10:00 AM Senate NGP
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* first hearing in first committee of referral
+ teleconferenced
= bill was previously heard/scheduled
+ teleconferenced
= bill was previously heard/scheduled
ALASKA LEGISLATURE
JOINT COMMITTEE ON NATURAL GAS PIPELINES
November 7, 2001
10:00 a.m.
SENATE MEMBERS PRESENT
Senator John Torgerson, Chair
Senator Johnny Ellis
Senator Donald Olson
SENATE MEMBERS ABSENT
Senator Rick Halford
Senator Pete Kelly
HOUSE MEMBERS PRESENT
Representative Joe Green, Vice Chair
Representative Scott Ogan
Representative John Davies
Representative Hugh Fate
HOUSE MEMBERS ABSENT
Representative Brian Porter
Representative Reggie Joule
OTHER LEGISLATORS PRESENT
Representative Jim Whitaker
COMMITTEE CALENDAR
10:00 - 12:00 Washington D.C. update:
John Katz, Director, State/Federal Relations and Special Counsel to
the Governor; Duncan Smith and C.J. Zane, Legislative Advisors with
Dyer, Ellis and Joseph; Update on Senator Murkowski's energy
legislation
12:00 - 1:00 Lunch
1:00 - 3:45 Department of Revenue
1:00 - 3:00 Roger Marks, Economist, Department of Revenue
3:00 - 3:15 Ed Small, Cambridge Energy Research Associates
3:15 - 3:45 Larry Persily, Deputy Commissioner, Joint Pipeline
Office, Bill Britt, State Gas Pipeline Coordinator
4:15 - 4:45 U.S. Mineral Management Service
John Goll, Regional Director
John Larson, Geologist
PREVIOUS MEETINGS
July 17 & 18, August 14 & 15, September 19,2001
ACTION NARRATIVE
TAPE 01-21, SIDE A
Number 001
CHAIRMAN JOHN TORGERSON called the Joint Senate and House Natural
Gas Pipelines Committee meeting to order at 10:00 a.m.
MR. JOHN WILLIAMS, Mayor of Kenai, commented briefly, but due to
transmission difficulties, his testimony is not audible on the
tape.
CHAIRMAN TORGERSON recapped the Mayor's comments saying that the
main emphasis of the meeting was to spend a substantial amount of
time on the resources in Cook Inlet, existing industry, and other
industry that has looked at Cook Inlet to either supply the
resource or build their own industry. He continued:
This is very important to this community, since part of
our deliberations is how we can [we] give them gas, if
and when we need gas, to the Southcentral Basin. We've
heard some exciting news about discoveries that have been
bylines in the press. We hope to elevate those to guide
us over the next couple of days to see what actually
might be there and what we can count on for additional
resources.
MR. JOHN KATZ, Director, State/Federal Relations and Special
Counsel to Governor Tony Knowles, testified:
Let me start by briefly describing the public policy
arena here in terms of five specific factors.
1. In terms of national energy legislation, I think it is
pretty clear now that we will not see that legislation on
the Senate floor before the Thanksgiving recess. Majority
Leader, Senator Daschle, has indicated five priorities
for Senate action in the immediate future and energy
legislation is not one of them. It seems increasingly
likely, though not certain, that there will be a session
of the Senate of the period between Thanksgiving and
Christmas. If that is the case, it is possible that
energy legislation will be introduced and perhaps brought
to the Senate floor for debate and voting.
2. The second factor that I wanted to bring to your
attention is that in a very rare parliamentary maneuver,
the Majority Leader of the Senate has basically brought
the development of energy legislation under his personal
aegis. In essence, he has instructed the chairmen of the
various committees that have jurisdiction over energy
issues to make recommendations to him. He and his staff
have taken the responsibility for putting those various
provisions into final form for debate on the Senate
floor. In the case of the natural gas pipeline, the
Senate Energy Committee has discontinued its markup of
energy legislation. Those markups began in August. Now
the chairman of the committee, Senator Bingaman, and his
staff are in the process of developing recommendations to
provide to the majority leader. We've been told that
their goal is to make those recommendations to the
Majority Leader in the form of legislative language by
this Friday. I'll come back to that later.
3. The third point that I wanted to bring to your
attention is that the Republicans in the Senate have
grown increasingly impatient with the pace of energy
legislation in the Senate and at various times they have
indicated their intention to develop an alternative bill
of their own to bring to the Senate floor. That effort
has not been totally successful so far. It has foundered
perhaps on provisions relating to ethanol and to
electrical energy restructuring, not anything that
relates specifically to the natural gas pipeline. Another
possibility in this scenario might be for the Republicans
to take the House bill, HR 4, and propose that as
amendments on the Senate floor to other fast moving
legislative vehicles. As many of you will remember, HR 4
contains a specific prohibition against the over-the-top
route for the natural gas pipeline and also includes
provisions, which would authorize oil and gas exploration
and development in the Coastal Plain of the Arctic
National Wildlife Refuge.
Another factor that I think is quite relevant in this
period is the relationship between the natural gas
pipeline and ANWR, itself. I think it is safe to say that
in the Senate, there's broad bi-partisan support for the
proposition of developing and commercializing Alaska
North Slope natural gas. There are key questions
concerning the legislation to accomplish that purpose,
but the basic proposition is not in question. However,
there are members of the Senate, including the Majority
Leader, and the Chairman of the Senate Energy Committee
who would like in essence to remove ANWR from the Senate
debate and substitute in lieu thereof the natural gas
provisions, perhaps some provisions relating to tax
incentives for heavy oil, treatment of stripper wells,
and other provisions relating to oil and gas, but not
ANWR. The Senate Majority Leader in floor statements and
in press briefings has indicated his strong support for
the natural gas pipeline as a hydrocarbon alternative
along with other provisions for ANWR. He talks about the
jobs that would be created with the gas line and other
advantages to the country. Conversely, there are other
members of the Senate who want to make sure that that
linkage doesn't occur and the parliamentary scenarios
that they envision would ensure that the gas line and
ANWR are considered separately and are both voted on in
the Senate.
The final factor, which is relevant to the specifics of
the natural gas pipeline is the position of the federal
administration. I think it's safe to say that the formal
position of the federal administration is to be project
and route neutral and not to propose legislation relating
to the gas line at this time. I believe that there's also
a great deference to the political leadership of Alaska,
the Congressional delegation, the Governor, the state
legislature in terms of what we think and how that is
factored in by the President and Vice President. They
also support the commercialization of North Slope natural
gas, but their principle focus, I think is safe to say,
has been on ANWR.
There are, I believe, three pivots in the Senate -
Senator Murkowski, Senator Bingaman, and Senator Daschle,
as we consider natural gas pipeline legislation. There
are several factors, I think to look at, as those parties
consider the issue. The first is whether to include the
producers' enabling legislation in the energy bill,
itself. I won't elaborate on that legislation now unless
you want me to since we've discussed it previously or the
alternative to rely on the ANGTA regime, which was
enacted and decided in 1976 and 1977 by Congress and the
President.
Another factor of chief determinant is whether the gas
pipeline should be considered within the context of
national energy legislation or perhaps as free-standing
legislation. A fourth factor is should that legislation
be route and project neutral or should it prohibit a
particular route, for example, the over-the-top route.
Finally, another very important determinant is whether
there will be tax incentives in the final package in
order to promote commercialization of North Slope gas
generally or to influence the choice of route by perhaps
providing tax incentives to only one route and not to
others. You've just heard the chairman's comments on
Senator Murkowski's work with respect to the gas pipeline
and I would not presume to add very much to that
description. Senator Murkowski is clearly looking at the
advisability of introducing legislation and, if so, what
the components of that legislation should be, whether it
should rely on the matrix of the enabling legislation or
in the alternative on the ANGTA regime. I think it's best
to leave that at that junction pending anything further
from Senator Murkowski or his staff that they would want
to share with the committee later on.
The second determinant that I mentioned earlier, is
Senator Bingaman. Even though markups are no longer
occurring on energy legislation in the Senate Energy
Committee, he and his staff are working very diligently
on several different provisions including provisions
concerning the natural gas pipeline and I believe it is
their goal to make their recommendations to the Majority
Leader at the end of this week, if that's at all
possible.
My guess, and it is only a guess, and I may be
contradicted by what actually comes out later, is that
that legislation will rely very heavily on the producers'
enabling legislation and that it will at this juncture
stipulate a particular route. I believe that Chairman
Bingaman is also very interested in developing some
economic incentives or tax incentives to commercialize
North Slope gas. I know that he and his staff are looking
at a spectrum of possibilities which include accelerated
depreciation on construction; secondly, reducing the
commodity risk by establishing some sort of floor price
and; third, even the possibility of an investment tax
credit, but those matters are not within the jurisdiction
of the Senate Energy Committee. They are, in fact,
province of the Senate Finance Committee, Senator Baucus'
Committee. It is by no means clear at this point whether
there will be any of these tax incentives in the Majority
Leader's final bill and, if so, what provisions they
might be.
The third pivot is the Majority Leader. He is pivotal
obviously in two respects. One is within broad
parameters, he will control the Senate floor; he will
control the timing of Senate consideration. He will
decide when to introduce legislation and then later when
the debate will occur. Of course, those decisions could
be overridden in various parliamentary ways on the Senate
floor, but it is not usual that that would occur.
The second place where he will be very important is on
the substance of natural gas legislation, itself. In
various contexts, he has indicated his strong preference
for the southern route. He has not yet, to my knowledge,
indicated publicly whether he would support the ANGTA
regime or the producers' enabling legislation, but he is
clearly knowledgeable on this subject and, as I indicated
earlier, would actually like to substitute the gas line
and some other oil and gas provisions for ANWR. He wants
to give a broad deference to his various committee
chairmen as they formulate different elements of the
energy package, but he has reserved to himself some of
the final decisions on what that package will look like.
There are other members of the Senate who have expressed
an interest in natural gas legislation, some for the
enabling legislation and some for the ANGTA regime, and
specifically for the southern route and they are part of
the dialogue now with Senator Bingaman and Senator
Daschle about how this will ultimately proceed.
In terms of the various advocates in the process who are
treating the Senate on the gas pipeline issue I think
you're going to be hearing from various proponents and so
I will only briefly for the purpose of this testimony
characterize what I understand to be the position of the
parties as they continue to advocate those positions. The
North Slope natural gas producers have remained very
strong advocates for their enabling legislation, which
they allege to be route and project neutral and simply to
present an alternative to the ANGTA regime. They have
also indicated that that legislation is absolutely
crucial in their deliberations about whether to go
forward in the effort to commercialize North Slope
natural gas.
Foothills and some of the other previous partners in the
Foothills project have indicated their strong preference
for the ANGTA regime perhaps as amended by some
legislative language that they proposed, which would
focus on the environmental process and confirm the
decisions made by the executive branch in 1977. They
believe that that legislation is the quickest way to
commercialize North Slope gas and to generate jobs and
they also feel that if there's any alternative to that,
the calendar may then become free to adopt an alternative
to the ANGTA regime and the international agreements that
form part of that regime. The State Administration has
continued to advocate the Governor's 10 principles as
described in his testimony to the Senate Energy Committee
in October. We continue to place heavy emphasis on the
ANGTA regime and particularly on the southern route. I
think in those respects our advocacy has been quite
similar to that of Chairman Torgerson and the principles
that the Joint Committee has adopted. We've also
emphasized the other principles in that package or
policy. Recently, we have felt that for the most part our
position and the position of the legislature are well
understood by members of the Senate and so the Governor
has shifted some of our focus to the commercial world. I
should mention that when the Governor was here we met
with many members of the Senate Energy Committee to
express our support for the pipeline for the southern
route and also for ANWR. We've since followed up on that.
In terms of the commercial situation you will hear in
greater detail from the pipeline companies, themselves,
but I think they would tell you that they are on track to
reconstitute their partnership and to deal with the very
important issue of the contingent liability, the $4.2
billion matter that we've discussed previously and that
sometime in the not too distant future they will be
prepared to discuss more formally with the producers how
they might jointly proceed, but I'll leave those
commercial presentations to others.
Finally, I would say that I think I've accurately
described what the situation is today, but it's very
fluid. It could be influenced by any number of
permutations and combinations in the Senate, itself, and
it also could be influenced by external events relating
to supply price and possible supply dislocations.
10:24 a.m.
REPRESENTATIVE GREEEN asked if the switch in leadership was good
news or bad news in terms of getting this issue to the floor and
not be bottled up in committee.
MR. KATZ replied that is a good question and that this is only the
second time that anyone could recall that this parliamentary
maneuver has occurred. He thought it was a setback. He said that
Senator Daschle is on record as supporting the southern route and
he thought Senator Bingaman was inclined toward a more route-
neutral approach. He didn't know how that would be resolved. Also,
the Majority Leader felt that the pace of activity in that
committee and other committees with relevant jurisdiction was quite
slow and maybe the best place to speed it up would be in his office
inviting all the relevant committee chairmen to submit their
recommendations to him. He commented, "It's not a particularly
democratic process at this point, but I think it is an effort to
get a comprehensive bill done."
MR. KATZ said it was a setback for everyone who supports opening
ANWR, because they thought they had the votes in the Energy
Committee. However, the Majority Leader who opposes ANWR did not
want to see a bill come out of that committee with ANWR in it.
He guessed that there wasn't sufficient time in this session of
Congress to both introduce a bill and debate it. He thought the
best that would happen is that a bill will be introduced that would
be debated some time next year unless the Senate adopts the House
bill, which is highly unlikely, and then there would have to be a
conference committee. There are a lot of factors that bear on the
answer to this question.
CHAIRMAN TORGERSON asked if he had heard anything from the
environmental community about routes.
MR. KATZ replied that they had commented, but not with great vigor
yet. They are very much into the ANWR gas pipeline dynamic. They
object to the northern route, some support the southern route and
some simply don't oppose it. He thought it would help the
democratic majority if they voiced their opinions.
CHAIRMAN TORGERSON said he asked that question because the
producers' legislation mirrors many provisions in ANGTA. One is the
limited judicial review process for challenges, which the
environmental community is not very enthusiastic about. He
questioned, "…is it just something that we don't have a bill in
front of us where they're holding back in the weeds until they see
something actually in writing?"
MR. KATZ said it might be more of the later and he hadn't seen them
get to the level of detail that is suggested by his question.
For the most part they're focusing on ANWR to the extent
that they're focusing mainly on the choice of route.
Although, when the details of the legislation come out, I
would not be at all surprised to see them focus on the
expedited judicial review issue. But it is in ANGTA and
it is in enabling legislation. It's a principle that I
think a lot of people endorse at this point.
CHAIRMAN TORGERSON asked where the legislation was that the
Governor said he was going to have Mr. Katz draft and introduce to
Congress as a guideline.
MR. KATZ replied that it is drafted, but it hadn't been given to
anyone. He said it wouldn't be productive for them to propose
actual legislative language at this point. If circumstances change,
they can do it.
10:32
MR. DUNCAN SMITH, Dyer, Ellis and Joseph, Washington, D.C.,
(testifying via teleconference) said he placed the call, but C.J.
Zane would comment.
MR. C.J ZANE reported that, from their perspective, people in
Washington D.C. are trying to figure out how to deal with ANWR. He
noted, "There are lots of moving parts here." He said the energy
bill could move quickly to the floor if ANWR were to be dealt with
in some other way. He said that Senator Daschle was going to put
some kind of energy bill on the Senate calendar, so it is available
if favorable circumstances arise. He thought that Foothills would
have more political momentum going if it could have the withdrawn
partners issue resolved and it has been working diligently to pull
the deal together.
MR. ZANE said that Senator Murkowski had draft legislation "that he
wants to keep in his hip pocket, but my latest 'intel' is that it
is not being laid on the table in any official capacity at this
point."
MR. SMITH added that the last time a Majority Leader took a bill
out of committee and took control of it was in 1960. The situation
is very fluid and it's all within the control of the Majority
Leader.
REPRESENTATIVE GREEN asked if he foresaw sort of a quid pro quo
that could pull ANWR out of the loop.
MR. ZANE said that the delegation is taking the position that, "You
don't get our gas in exchange for us giving up ANWR. You'll get our
gas, which you've already said you need, if we get ANWR. In the end
ANWR will help continue the potential for even more gas delivered
to the Lower 48."
He said that Senator Daschle would like to use this as a quid pro
quo and the delegation is aware of that and is working very hard to
see that that doesn't happen. They are considering attaching it to
the economic stimulus package that the President really wants or by
attaching HR 4, the House bill that contains ANWR, to one of the
packages.
MR. ZANE said further that:
All of these moves and counter moves in the end are
interrelated so that you could end up with an energy bill
with ANWR and a gas line provision in it, but only after
Daschle agrees to some parliamentary procedure that lets
ANWR have its day on the floor. Some of the Democrats
will make the argument that we'll vote against ANWR and
vote for the gas line. I think that efforts will continue
to separate the issues and I think that our delegation
will not be comfortable with a gas line bill where there
hasn't been some accommodation made on ANWR. If that
combination and deal gets made, it could happen this
year. If it doesn't get made, then the idea is to go into
next year.
TAPE 01-21, SIDE B
10:26 a.m.
REPRESENTATIVE GREEN asked what the chances are of it happening
this year.
MR. ZANE said there is about a 20 - 25% chance that the ANWR issue
gets resolved satisfactorily so that we also get an energy bill
this year.
REPRESENTATIVE DAVIES asked what the chances are that we get
neither this session.
MR. ZANE replied:
It's too simple to say it's the reverse of what I just
said - that it's a 75% chance that we get neither,
because I actually think that we have a little bit better
than a 75% - I would say that we have about a 50/50
chance of getting ANWR dealt with this year on some other
vehicle, some other legislative package. I say that
because the delegation wants it; the White House wants to
see it happen, in my view. We have a 50/50 chance of
getting ANWR, but it doesn't necessarily translate then
that we have a 50/50 chance of getting both. I do think
our chances of getting both are much better once you have
ANWR dealt with.
CHAIRMAN TORGERSON said:
Well, C.J., you know our position is just to reaffirm
ANGTA. So we're not really pushing for gas legislation.
I've heard two different stories on what might be in
Senator Murkowski's legislation. One is starting with the
producers' legislation and then three or four other
provisions. The other one reaffirming ANGTA, well first
the producers would have to [indisc.] Foothills and have
to get their act together within a certain timeframe. So
they would have the first right of refusal. My
understanding is under the producers' legislation it
would transfer to Foothills to do that and the other one
that I heard is actually from Mr. Katz and it's just the
opposite of that. It reaffirms ANGTA for a period of time
and then if they didn't perform under ANGTA, they would
revert to the Natural Gas Act and approve the producers'
legislation.
CHAIRMAN TORGERSON asked them to chase down the answer to that
question. He said:
This committee has voted to uphold the provisions of
ANGTA, but if it's the wisdom of Congress to adopt the
producers' legislation under the Natural Gas Act, then
we've got several hundred pages of amendments that we
want them to consider along with that.
MR. ZANE responded they understand and they have passed that on.
10:52 - 11:03 a.m. Break
MR. ZANE continued to say that Senator Murkowski's draft
legislation was never something he was committed to; he wanted
staff to put concepts down on a piece of paper to see what they
would look like. He has heard from several people on that, but he
is in no way ready to move. It would bar over-the-top; it would
give prominence to the existing ANGTA law and the Foothills
project, but only for a period of time, like a couple of years. He
continued:
If an agency, like FERC, were to certify that an official
application had not been filed by a certain date, then
after that date, certain other provisions in this draft
language would become effective, like the ability to file
for a second southern route under the Natural Gas Act
with its own set of judicial and environmental review
provisions in it that are different than the ANGTA
provisions. In other words, the environmental [indisc.]
and expedited review provisions in ANGTA would stay in
effect through the time where the FERC conditions would
kick in if nothing gets going on the Foothills project.
CHAIRMAN TORGERSON said he thought there were a couple of other
provisions; one was access by non-producers into the line. He said:
I'm not too sure this committee would oppose that as long
as we do it in sequence of reaffirming ANGTA for a period
of time, giving that period of time to the owners of the
franchise, Foothills or whoever ends up gobbling up all
of Foothills, Duke or West Coast or TransCanada, and give
them a reasonable length of time to formulate their
proposals, which we know they're working on now and then
if that all boils up so that the project doesn't
completely go away, then it would revert to the same sort
of conditions to the producers. We haven't taken a
position on that as this committee, but my guess is that
isn't too far from our original point.
MR. ZANE said the important thing about the language is that
Senator Murkowski is looking for a way to lock ANGTA in, at least
for some period of time after which they get sunsetted out.
CHAIRMAN TORGERSON reiterated that they didn't oppose that as long
as the timelines are right.
REPRESENTATIVE DAVIES asked if after the FERC certification
happened, were the other provisions substantially similar to the
producers' legislation that the committee has seen so far.
MR. ZANE said he thought it was more likely to be what Senator
Bingaman proposes rather than the producers. He wasn't sure that
the producers liked this. He knows they don't like the
reauthorization of ANGTA.
REPRESENTATIVE DAVIES asked if it wouldn't be hard to actually put
a project together under ANGTA if the producers were dragging their
feet. "It still puts the producers' bill in the drivers' seat in my
opinion. Could you comment on that?"
MR. ZANE replied, "I think you have to ask Senator Murkowski and
his staff those questions."
He assumed if the Foothills project can really get going, major
U.S. companies would be involved who on their own can be
significant in terms of capital for the project and political
clout. It's possible the producers would see that it's not
beneficial to drag their feet.
CHAIRMAN TORGERSON said they should remember that the producers are
authorized to be partners, also. They are the ones who are pushing
for the 82 amendments. He asked if there were any further
questions for Mr. Zane or Mr. Smith. There were none and he thanked
them for keeping the committee informed.
[END OF TAPE]
11:19 a.m. - 1:08 p.m. Lunch Break
TAPE 01-22, SIDE A
MR. ROGER MARKS, Economist, Department of Revenue, was the next
speaker. Chairman Torgerson had asked him to put together some
models on netback and different aspects of the economics.
MR. MARKS said that he had presented the committee with an economic
model in July and was asked to come back and present it in more
detail. He said when looking at the models the focus is on what it
means for something to be economically feasible. He explained:
One of the crucial issues that determine economic
feasibility is how risky a project is and how that comes
in to determining feasibility. That's why I really wanted
to spend some time discussing how risk and especially in
the context of this project, how commodity price risk,
that is the price of gas and how it affects the riskiness
of the project and the economic feasibility of the
project.
We're going to talk about the commodity price risk. It's
useful to just pause for a second and discuss how the
price of gas is established. Getting away from gas and
just talking about any commodity, the price in the market
for any commodity will equal the lowest cost to produce
new supplies.
What does that mean? If we take an example of something
that has nothing to do with gas, let's just say I invent
a robot that will change the oil in your car and let's
say I can produce that robot for $100. I figure people
will pay $500 for this robot, so I manufacture these
robots for $100 and sell them for $500 and make a lot of
money. Well, pretty soon someone will come along and say,
'Gee, this guy is spending $100 to produce something and
selling it for $500. I can produce that thing for $100,
too, and I'll sell if for $400 and take all his business
away. Pretty soon, someone else will come in and say,
'Well, I can sell if for $300 and eventually the price
will come down to the cost. In economic terms it's called
the marginal cost and the marginal revenue. The marginal
cost is the cost to produce the unit and the marginal
revenue is the price. Basically, in markets, if they're
operating properly, the price of that commodity will for
the lowest cost to produce new supplies.
How might this come into affect for North Slope gas?
Let's say the price in the Midwest in the Chicago area is
$3.00 - the market price for natural gas, whether it
comes from Alaska or whether it comes from Louisiana.
Let's say that people figure out they can make money
building a North Slope gas line if the price in Chicago
is $3.00. Then all of a sudden, Venezuela looks up and
says, 'Gee, we have a lot of gas here and we're
interested in selling LNG in the United States and we
think we can bring LNG into the United States at a cost
of $2.00 and make money selling it for $2.00. So what
happens is at that point, if you have power plants in the
United States or a local distribution company, you say,
'Gee, I can buy gas in Louisiana or Alaska for $3.00 or I
can buy gas from Venezuela for $2.00. At that point, the
same process that happened with the robot would happen
with gas and eventually the price of gas would come down
to $2.00. With that sort of help the price is established
and since if you're someone who's thinking about
producing gas and building a pipeline to bring North
Slope gas to market, you have to be concerned about what
the price of gas is going to be in the future. Because
the price of gas is so volatile and so unknown, there is
significant gas price risk facing someone who decides to
build a project.
The question then becomes who will assume this gas price
risk and how will they assume it. One way, and this is
how if things are evolving the way I see it, I believe
what will happen at some point in time is the North Slope
producers decide to go ahead with this project, they will
have a third party build and operate the pipeline and
they will pay someone to build the pipeline and they will
ship the gas, someone like Foothills, Enron, Duke or El
Paso or Williams.
If the project is structured like that, the only way a
pipeline company will get financing to go the project is
if the producers make throughput guarantees if they
guarantee they will pay to ship a certain amount of gas
for a certain amount of time. That way the producers
would assume the gas price risk. If the producers assume
this risk and let's just decide Duke Energy, for
instance, is going to build this, and they go to the bank
and say we're going to build this and their bankers say
to them, 'Okay, what you have to do is get a throughput
agreement. It's going to be a 4 bcf/d line and we figure
the tariff is going to be $2.50. If the producers, Exxon,
Gulfs and BP, say, 'No matter what, they will pay $2.50
for 4 bcf/d for 20 years, if they guarantee to pay to do
that, then we'll finance the project.'
Well, if that happens, let's say the producers commit to
pay $2.50 for 4 bcf/d for 20 years and then the price
drops to $2.00 like we talked about a few minutes ago,
the producers could loose a lot of money. That's an
extreme example, but if they loose a penny on 4 bcf/d for
20 years, that's $300 million they would lose over 20
years, which is a lot of money. If they lost .50, like
they have up here that would be $15 billion.
Another way gas price might be assumed if, for instance,
these pipeline companies instead of having the producers
take the gas price risk, the pipeline companies come in
and say, 'Okay, we'll buy the gas from the producers on
the Slope for .50 or .75 or $1.00, we'll buy it from
them, we'll ship it and then we'll sell it ourselves in
Chicago. That way the pipeline companies would assume the
gas price risk. Either way, someone assumes the gas price
risk. If the pipeline companies assume it, then the
project becomes much riskier for them. The whole lynchpin
in this project is the gas price risk and who is going to
assume it.
I've talked to several of the pipeline companies over the
last couple of years and from what I understand them
saying is they probably are not going to assume the gas
price risk. That's not what they do. They build and
operate pipelines and that's why I said earlier, as this
project structure seems to be evolving, I believe the
producers, if it's built, will probably assume the risk.
But it's possible the pipeline companies could assume it,
as well.
While thinking about the project and those different
project structures that I presented, the question you
need to ask yourself is who is assuming the gas price
risk. It's also very important to understand that the gas
price risk is different than the pipeline risk. If we
have a project structure where if Duke is building the
pipeline and the producers are assuming the gas price
risk, the pipeline risk is much, much different than the
risk of the producers would take. The pipeline company
would certainly face risk. There's cost overrun risk,
there's environmental liability contingencies, it's
possible the regulators might not let them recover all
their costs.
But these risks are much different than the risks assumed
by someone who is going to live or die with gas price. I
believe these risks are less, as well. It's important to
understand, though, that someone building and operating
the pipeline is going to face a whole different set of
risks than a producer who is guaranteeing to pay the
shipped gas, no matter what the price is.
So, if you think about this gas price risk, what
companies are going to do is sit down and think about
what might happen to the price of gas and even though the
average price might be $3.00, they might say, 'Well,
there's a 50 percent chance prices might be $3.00, but
there might be a 40 percent chance it's $2.00 and maybe a
10 percent chance it's $7.00. That all averages out to
$3.00. But they'll look at that and say, 'Gee, there
might be a 40 percent chance we're going to loose money
on this and loose a lot of money. So, they're going to
look at what they see as their distribution of possible
gas prices, look at what the loses might be, how big they
might be and how frequently they might loose money and
that's going to sort of shape how they view the whole
riskiness of this project.
When a company is doing a feasibility study or an
economic study on the viability of a project, the way
they address risk is through what's called the discount
rate. What the discount rate looks at is what kind of
return do we have to give investors to make them feel
comfortable investing money in this project. Every new
project needs cash and they get that cash from investors,
probably in the form of debt or the form of equity. The
company, when it's getting cash for a project, is going
to compete with investments from other projects. An
investor can invest in a gas pipeline in Alaska or he can
invest in an internet startup company in Silicon Valley.
All these investments compete with each other and the
investors are going to expect a certain rate of return
before investing. The important thing about this is the
amount of return that they expect to get for investing is
going to be commensurate with the amount of risk in their
project. For example, today I can buy a one-year T-bill
from the federal government backed by the U.S.
government. There's practically no chance that they'll
default, so I can invest $100 now and one year from now
get back from the government, I think interest rates now
are around 2 - 3 percent, and get $102 or $103 back a
year from now. On the other hand, if I'm an investor and
I'm trying to find an investment and I look on the
internet, people looking for investors and suppose I see
that some is starting up a travel agency that's going to
specialize in bringing people to Afghanistan today and
they're going to pay 3 percent. It cost them $100 to
bring people over, but they'll charge $103. I'm going to
look at that and say, 'You know, for the same $100, I
think it's a lot riskier investing in the Afghanistan
project than buying a T-bill from the federal government.
What kind of return would I expect to invest in the
Afghanistan scheme? Maybe I'd want 100 percent return. If
I put $100 down, I'd expect $200 back because the odds
are so risky.
The question with this project becomes what kind of risk
surrounds the price of gas. A project will generate cash
flows. In this project you'll be selling gas in Chicago
and you'll make money on that, no matter what the price
and you'll have costs. You'll have your tariff, you'll
have operating costs, you'll have taxes to pay. What
comes out of that are the net cash flows. The net cash
flows go to both the debtors and the shareholders and
this is the return paid to investors and this is called
the cost of capital. It goes to both debtors and
shareholders. It's sometimes called the weighted average
cost of capital or the WAC. And the rate of return that
these investors require to invest in this project is
called the hurdle rate or it's also called the discount
rate. In modeling projects, what a company will do is
they'll have their own assessment of what kind of return
given the risks that investors will expect from investing
in the project and that will become the hurdle rate and
if the cash flows don't generate a rate of return that
exceeds that hurdle rate, they will not consider the
project economic.
We might ask what happens if a project generates a rate
of return less than what the shareholders expect. Let's
say I expect a 15 percent rate of return in a project and
I invest $100 and it turns out it's only going to return
110 percent. What will then - if I'm still going to
expect 15 percent, what that means is that the
shareholder will only put $95 down, if I'm going to get
$110 back rather than $100. In essence, what that means
is that value of the stock goes down and corporations
these days are structured to make the lives of the
managers very miserable if the value of the stock goes
down. So, management is not going to do anything to make
the value of the stock go down, which is why they need to
earn a rate of return that investors expect given the
risk.
Again, I'd like to point out that this discount rate, if
we're addressing the project where someone like Exxon is
figuring out whether or not to have someone build the
project so they can sell gas and Exxon is assuming the
gas price risk, the discount rate they have is going to
be very different from the discount rate someone like
Duke is going to have to build a project. Numbers have
been thrown around that maybe there might be a 9 percent
cost of capital on the pipeline and a 15 percent discount
rate for the project. Those numbers are not inconsistent
at all. What they are is two completely different
investment decisions with different sets of risks.
Now the question is what might be the discount rate for
this project. Generally, when you try to figure out the
discount rate for a project, you want to figure out what
the risk or discount rates are of comparable projects
with similar business risks. It's not difficult these
days to look at different companies just to see what
their costs of capital are and see what discount rates
companies use as a whole. One reason is that projects
that have a discount rate, not companies. It's not hard
to figure out what Exxon's cost of capital is. However,
if Exxon decided to go into the airline business, they
would not use the discount rate they use for exploration
and development for oil and gas. They would use the
discount rate the airline industry uses.
This project we're talking about here is very unique and
it's difficult to find the proper analogue business risk
that would be comparable. For instance, something like
Enstar just has a gas distribution system in Southcentral
Alaska is not an appropriate risk analogue. The
exploration and development arms of these producers are
really not an appropriate dialogue. One can make the case
that a well-diversified exploration program is probably
not that risky. If you can make a lot of money off of one
well and you're drilling in five different places and you
think one of them is going to come in, that's a whole
different set of risks. Even other gas pipeline projects
are not appropriate analogues for this project and the
main reason why is simply their high transportation costs
for gas from Alaska. If the Prudhoe Bay gas field were
located in Indiana right now and it was 50 mile pipeline
trip to Chicago, that gas would be commercialized by now,
because it would be very unrisky. Alaska is
geographically about the end of the line in terms of
economics on gas projects. So, it's really difficult to
say what the discount rate is and each company looks at
it their own way. Each company will probably have a
different assessment about what the discount rate is and
I'll say right up front that I do not know what the
proper discount rate should be for this project. I'll
also say that this whole presentation has been sort of
surrounded in gloom. I wanted to represent what the risks
are and how bad the risk could be. Again, this is not to
say that this couldn't be a splendid project and there's
no advantage to companies to look at a project through
more risky eyes than what it really is, because if
there's an opportunity to make a lot of money, they will
do that.
What I'd like to do is also talk about a couple other
concepts before we get going, specifically in the model.
I would like to put up the model to show those ideas.
CHAIRMAN TORGERSON asked if he was going to comment on the press
releases where the producers say the gas lines are not economical,
because they make 11 percent and not 15.
MR. MARKS replied:
Basically, my model if you put the producers inputs into
them, I get the same outputs the producers get. As I said
in July, we are certainly not specialists on what the
capital costs of the project are and that's a big
determinant about what the answer is. So, we really don't
have an opinion on the veracity of the inputs. If the
inputs the producers have represented are indeed the true
inputs, I believe the outputs they have generated are
indeed the outputs. When they put up 11 percent as a
return, that is the return with those inputs. Again, I
have no idea what the right discount rate is. That 15
percent is something the three of them put together for
presentation purposes. I think each company has their own
different idea on what that number is.
CHAIRMAN TORGERSON asked if they would characterize 11 percent
return as a non-profitable project.
MR. MARKS replied, "There's a difference between profit and, again
with my Algerian project, you could earn 3 percent and not be
profitable. That does not necessarily make if feasible."
CHAIRMAN TORGERSON asked if they could explore that today, because
they need to get past the news releases saying that 11 percent is
not a profitable project. He knows the regulatory agencies
generally give pipelines between 8 and 12 percent return as a
built-in profit in their tariff. He assumed that they would like a
higher number because of the risks that might be involved, but it's
an uncharacteristically higher number as it relates to what our
regulatory agency gives.
MR. MARKS replied:
Let me answer your second question first. Again, if the
regulatory agency gives the pipeline a 9 - 12 percent
rate of return, that is not inconsistent with a producer
who needs 15 percent to make this project work, simply
because they're two different investment decisions. One,
the return a regulator would give a pipeline company, if
a regulator is going to give that return to the pipeline
company based on the risk they face, the pipeline company
is only going to get financing given the throughput
guarantees. With those throughput guarantees, the risks
the pipeline companies face, I believe, wants a lower
rate of return than what the producers would want facing
the commodity price risk. That's not to say that the
pipeline company doesn't have any risk. They do. There's
cost overruns; there's the possibility the regulators
might not let them recover all their monies and there
could be a gas explosion in the middle of downtown
Fairbanks or Edmonton, for instance. So, building a
pipeline is not riskless, but it's a less risky activity.
Again, what we have here are two different projects
facing two different profiles. One is a decision to build
a pipeline with a throughput guarantee. The other is the
decision to make that guarantee knowing you could
possibly loose a lot of money if gas prices go low.
To answer your first question, again, I don't know what
the discount rate is. It would be foolish for me to try
and say what that is. I could probably give you a wide
range, but the range would be too wide to be meaningful.
What we can do with the model is look at what rate of
return you get on your different inputs and how different
inputs or tax regimes or prices affect the rate of return
and see how close you get to a hypothetical target.
CHAIRMAN TORGERSON asked if the 11 percent rate of return includes
things such as the loss of oil production, if any, if we take 4
bcf/d off the fields. Also, he wanted to know if they are including
the netback of gas or is it just strictly pipe line economics.
MR. MARKS responded that he understood the 11 percent rate of
return is not predicated on any oil losses. He explained with the
use of his model.
REPRESENTATIVE GREEN asked what would happen to the rate of return
if they set this up at $2.50 and they find gas at $2.00. He also
wanted to know if the miscible liquids had been considered in the
netback value to the state. Those liquids could be extracted before
the gas goes through the pipeline and money could be made there.
MR. MARKS replied that in the example he used $2.50 was the tariff.
He didn't think it was possible to enter into real long-term gas
sales contracts for significant volumes.
There is no real market out there. You can't go to the
New York Mercantile Exchange and sort of hedge gas 20
years out. I don't think most power plants and local
distribution companies are willing to enter into long-
term contracts on the sales side.
On the second question, the liquids - this is what the
producers have told me and this how I believe they have
modeled it and how I've modeled it. They have told me
that the composition of the residue gas would be 1080
BTUs per mcf. However, the gas distribution system in the
Upper Midwest can only take 1040. For the other 40, they
said the cost of extracting the liquids would offset the
value of that extra 40 BTUs and it was a wash pretty
much. Some people have said that the residue gas might
have much higher BTUs; it's something the Department of
Revenue is not an expert on. But that's the best
information we have on that right now.
1:42 p.m.
REPRESENTATIVE FATE asked regarding the gas price risk if he or the
producers had a constant in the formulas which says that in the
future there may be a different process in establishing gas price
making the gas price risk more tolerable in the computation of
their return on investment.
MR. MARKS replied, "Yes, if you could lock in $3.10 for 20 years on
4 bcf/d, that would reduce the risk of a project and the hurdle
rate would be reduced as well."
REPRESENTATIVE FATE asked if there had been any constant computed
on, at least, the expectation that might happen. He explained that
he has heard people in the industry say that some type of pricing
mechanism is needed to stabilize the price of gas. "If that's true,
then the gas price risk would be leveled at some point and the
computations would be more bearable relative to the return on
investment."
MR. MARKS responded that he was not familiar with any proposed
ideas to stabilize gas prices. Consumers want the price to be as
low as possible and there would be resistance if there was any
effort to put a floor on prices.
CHAIRMAN TORGERSON commented that one of the producers asked some
members of Congress to entertain a floor on pricing.
If the price of gas went down to around $1.50, then there
would be some sort of royalty or dollar exchange to give
them downside protection, but that hasn't materialized.
I'm sure the answer to your question would be yes, it
would be less risky if they would have a government
guarantee. That goes without being said. I also don't
think there's anybody entertaining that currently, but we
don't know that either.
REPRESENTATIVE FATE responded that was why he wanted to know if it
had been introduced as a variable in any modeling.
CHAIRMAN TORGERSON responded that it hadn't been introduced, but it
hadn't been thrown out either. He thought it would be an upward
battle.
REPRESENTATIVE DAVIES clarified that he thought part of the
question was whether it was a factor in Mr. Marks' model and he
heard the answer to be no.
REPRESENTATIVE OGAN asked if it was correct that a long term gas
contract was for about one year.
MR. MARKS said he wasn't sure, but probably not much more than
that.
REPRESENTATIVE OGAN asked if anyone had considered what the energy
market would be in 2040.
MR. MARKS replied that the reason it's difficult to do that is
because for years the gas price was $2.00 until about a year and a
half ago when prices shot up to $10.00. That happened mainly
because inventories were very low and last winter was the coldest
winter in 100 years. "The big unknown is what happens to supply
when you go from a $2.00 well to a $3.00 well. There's basically a
continuous line at any time the price goes up."
He explained that all of a sudden the gas that cost $2.50 - $3.50
to produce that wasn't economic before becomes economic. No one
knows what the shape of the line would be - whether a whole bunch
of gas would come on line or a little bit. He thought that when
prices shot up, most analysts underestimated the amount of
additional gas that would come in. So, it's difficult to forecast
what happens 10 years from now. "Alaska would be just about the
most expensive gas on the market when it comes in."
MR. MARKS said he wanted to further explain the discount rate
issue. He said that the discount rate represents the return to both
debtors and creditors. "It's a weighted cost of capital that's an
average of your debt and your equity."
TAPE 01-21, SIDE B
1:55 p.m.
MR. MARKS said there might be a question of why there are no
interest payments if you are incurring debt. He answered:
The way corporations do their modeling is they assume you
have all equity financing with no explicit debt payments.
Therefore, your cash flows go to pay off both the debt
and the equity. That rate of return, the 11.1, is called
the return on investment.
The alternative way to do this would have been to
actually model in the debt payments. What happens then is
since you're leveraging, since your rate of debt is less
than your rate of equity, what you're left with then,
your cash flows would be greater; but, since you paid off
your debt, what you're left over with in the net cash
flows goes on the equity. So your discount rate instead
of being the average cost of capital, it's your average
cost of equity, which is greater. But, in general, the
results you have would be the same in terms of
feasibility or not. But, what corporations do is model
all equity with an average cost of capital as a discount
rate.
The other thing I'd like to point out is from what people
say, 'Why don't you just leverage the whole project? Why
couldn't you borrow 100 percent at a low rate?'
What happens even if you could get 100 percent debt
financing, which you couldn't, but, if you could,
theoretically, what happens is that every time you incur
more debt, the next set of debt you incur is more risky,
because people who are incurring debt in the back of the
line aren't in the back of the line. They're going to get
paid off after the people in front of the line. If you
incur more debt, what that does is make your cost of debt
at the end of the line higher. Or, if you do have
shareholders behind the debt holders, what that does is
make the shareholders' investment even more risky,
because there is not only more debt in line in front of
them, but it's higher cost debt. The finance theory says
and actually two economists want to help [indisc.] in
proving this that the weighted cost of that much capital
is actually indifferent to your debt equity structure. If
you try to do more debt to help a project, what happens
is your cost of equity goes up and your weighted average
cost of capital is unchanged.
CHAIRMAN TORGERSON asked how he treated property tax (ad velorem
tax).
MR. MARKS replied that for the pipeline there was a four-year
construction schedule and, "each year you start paying property tax
as soon as it goes in the ground even before revenues are
generated."
He said the model shows how things work and answers questions. He
again read a caveat that he had read in July that says, "The
following numbers do not represent what the Department of Revenue
believes the economics of the project are. They simply represent
what the economics would be and with the specified inputs. The
Department especially claims limited expertise as to capital
costs."
He explained that he just used the peak revenue year of 2015 for a
project that starts in 2007 and state revenues would be $626
million. He continued to explain his slides.
CHAIRMAN TORGERSON asked if the economic limit factor (ELF) kicked
in immediately on Prudhoe Bay gas.
MR. MARKS replied that there is an ELF on Prudhoe Bay gas right
now, although there are very small volumes that are sold to the
refinery. The ELF gives approximately 300 tax-free barrels of oil a
day or 3,000 MCF/D of gas.
If oil and gas come out of the same well, which they will
in this case, the tax-free treatment is pro-rated between
the oil and gas. So, with a gas sale, basically you have
relatively less tax-free oil and so the oil ELF goes up.
CHAIRMAN TORGERSON asked if he was predicting there would be zero
loss of oil after they depressurize the field. He also asked what
they should use for a fair comparison of projects, like LNG Al-Can
route and the GTL project. He asked, "Which one makes the producers
more money and which one is best for the State of Alaska?"
MR. MARKS replied no to the first question. He said further:
If the producers are going to do the project, whether
it's GTLs, LNG or a pipeline through Canada, there's no
project that they will do if it's not economic to them. I
don't see the state doing this project. If they're doing
it, it has to make sense to them…. So, the first thing
you have to look at is the rate of return. Different
projects, again, are going to face different risks and so
each project will not have the same discount rate.
CHAIRMAN TORGERSON asked how he got his rate of return.
MR. MARKS replied that the rate of return was the internal rate of
return from [indisc.]. "The reason it dropped from 11.11 to 10.77
is because I just put in the oil losses now.
CHAIRMAN TORGERSON asked if he compares three categories, the well-
head, the total state revenues and the rate of return, between the
different projects would they have a good feel for which one pays
the state most and pays the producers the most.
MR. MARKS said that was fair, but to keep in mind that different
projects have different discount rates.
2:06 p.m.
REPRESENTATIVE GREEN said the affects the loss of oil would have
bring to mind the questions:
Will there be and when will there be a loss of oil? Is it
going to be immediate or is it going to be down the road
a ways. If it's down the road a ways, is the value of the
lost oil discounted at the same rate that we're
discounting these other things…
He also asked if the items in the model could be changed one at a
time to find the sensitivity.
MR. MARKS replied, "Absolutely…"
He continued to explain that their oil loss model uses information
in a document from ARCO's oil loss announcements during royalty
litigation in 1992 (with their permission). The Department started
modeling the commercialization of North Slope gas around 1996. ARCO
said that it would be okay to publicly show the oil losses for this
exercise, but that he couldn't show the actual model, itself. He
has been told by oil companies now that thinking has changed and
what they thought in 1992 for oil losses was too high, but they
haven't talked about what they think quantitatively the losses are.
His model shows the oil losses as a function of when the gas sales
start, how fast they ramp up, and how much gas is sold. It's
basically a total amount of gas that has been depleted from the
reservoir over time and that's why the losses start out small and
grow.
CHAIRMAN TORGERSON asked why there was the NGL loss.
MR. MARKS replied that was because the gas was used to pressurize
recovery in the reservoir for the NGLs as well as the oil.
CHAIRMAN TORGERSON said if we're producing more gas, we should have
more NGLs. He continued to discuss figures in the model with Mr.
Marks.
MR. MARKS said that the big utilities in Asia have traditionally
structured their pricing with formulas tied to crude oil prices,
which had nothing to do with the cost of producing the commodity,
but that was changing.
Going forward, the whole gas purchase structure in Asia
is being decentralized on a much more profit-oriented
basis where individual power plants and individual gas
distribution companies are going to be buying their gas.
It's going to be deregulated. It's going to be much more
competitive and I believe a gas structure in Asia will
tend towards a structure where a purchase price will have
something to do with the cost to produce it.
What that does is put Alaska at a tremendous
disadvantage, because there's a tremendous amount of gas
in competing jurisdictions in the Mid-East, Qatar,
Abudabi (ph), Asia, Malaysia, Australia, Indonesia,
Sakhalin Island and basically that gas is sitting at
tidewater and doesn't have to bear the burden of a
pipeline.
Pretty much you can liquefy gas for the same cost
anywhere, ship it for the same cost anywhere. You can say
that Alaska might have some distance advantage over the
Mid-East. The cost of shipping LNG over the last two
years has come down drastically, so even big differences
in shipping distances are not that important.
Furthermore, what we can tell pretty much is all of
Asia's LNG contracting needs, at least to the end of this
decade, have been met. Alaska, to bring the cost down,
would have to sell a tremendous amount of LNG, which is
far more than anyone is going to be looking for, at least
in this decade.
He said using this structure, you go for oil price risk instead of
gas price risk as the risk factor. He thought over time, the price
of gas in Asia would represent what the cost to get it there will
be.
CHAIRMAN TORGERSON asked if he had included the Port Authority
numbers in any models.
MR. MARKS replied that they are selling volumes that aren't even
discovered, yet. Their model uses 6 bcf/d for 30 years, which is 65
tcf, almost twice as much as has been discovered.
CHAIRMAN TORGERSON asked him about the GTLs.
He commented on GTLs, that once the product is made on the North
Slope, you would deliver it to the oil pipeline. So, there isn't
the problem of scale that you would have with LNG or the Canadian
pipeline. You don't need a huge project to bring the cost down. He
said:
The other notable thing about gas to liquids is the big
problem with Alaska gas that geographically, it's pretty
much at the end of the line. In these LNG and Canadian
gas projects the transportation costs just chew up the
value. With oil, maybe 25 percent of the value gets eaten
up by transportation; with gas it's about 90 percent.
With a GTL project using the trans Alaska oil pipeline,
the variable costs of using the oil pipeline are fairly
low, in the order of maybe 20, 30 or 40 cents per barrel.
Once you get the gas to tidewater in Valdez, you can
compete with other projects in the world. You get on
equal footing with other competing projects a lot easier
since you have the oil pipeline to work with and the
costs are low. Again, you don't have the transportation
costs eating up the value like you do on the other one.
What we modeled was a three-train project - each train
producing 100,000 barrels per day of this high value
clean gas product, part diesel and naptha. The price
Exxon was looking at two years ago was about $35,000 per
barrel capital costs at peak. I've reduced that to
$30,000. If you read the literature, people are even
thinking about costs as low as 20,000 in projects going
on in Africa now. People think it would cost more to
build something in the Arctic. They put factors up to 50
percent or so on that. So, I've used $30,000 here.
There's talk about Shell and [indisc.] building up in
Nigeria now for $20,000. So, what that amounts to with
100,000 barrels per day peak, a total CAPEX of $3 billion
per train.
What you're getting is about .11 barrels of the product
per thousand BTUs. These are the price premiums in the
market today you can get for clean car diesel on the West
Coast for naptha. In Asia, you get about 30 percent over
crude oil for car diesel and 15 percent over crude oil
for naptha. Again, what you're doing is playing the oil
price risk roller coaster with a project like that.
Pretty much you have the same tax structure that we had
in the other projects. Looking at the cash flows…
CHAIRMAN TORGERSON asked how many bcf/d 100,000 barrels was or was
it all in BTUs.
MR. MARKS 872,000 MCF going in to produce 100,000 barrels of the
product.
CHAIRMAN TORGERSON asked what the rate of return was.
MR. MARKS replied that it was 8.87 percent.
REPRESENTATIVE FATE asked what the equivalent was in bcf/d.
MR. MARKS replied, "Remember this is only a 2.6 bcf/d, so these are
no comparables in terms of volumes."
CHAIRMAN TORGERSON asked if it is safe to say that the State makes
more money on GTLs in the pipeline.
MR. MARKS replied:
In general I would say, with all things equal, generally
a product that's tied to oil would probably be more
profitable than one kind of gas, for no other reason than
you have a cartel propping up the price on oil-based
products. So, if indeed the price is tied to oil, that
will affect the bottom line. It's just what the price of
these commodities turns out to be.
REPRESENTATIVE GREEN asked, when he did this model, if he reduced
the tariff on the oil, because there is more throughput.
MR. MARKS said that was right.
REPRESENTATIVE GREEN asked if other considerations were involved in
his model, for instance if there were no new discoveries and they
could still have GTLs coming through the pipeline, keeping it
viable.
MR. MARKS showed him a chart of oil volumes and said:
Here's an example of what tariff reductions are as a
result of the GTL volumes. It starts at 12 percent, but
after the late years of the North Slope when oil volumes
are low, the tariff reductions get sizeable. Who knows
what the volumes are going to be, but just with the
inputs I have here, you have a $4 per barrel reduction in
the year 2038. I'm sure it won't turn out that way, but
at least it's being considered.
2:40 p.m.
REPRESENTATIVE OGAN asked when he figured the royalties to the
state, whether he figured on well-head price on gas or the royalty
based on a barrel by crude at processing.
MR. MARKS replied that he figured it based on gas:
It's 12.5 percent regardless of whether it's oil or gas,
but what you have is gas being produced. You don't have
the well-head, which is the point of production when they
royalty is assessed and going through this processing
activity. Your closest value at the end is just netted
back and that total gross value is divided among the
total units of gas going in.
REPRESENTATIVE OGAN asked if he was saying it would basically be
awash after they [indisc.] the 40 percent of gas.
MR. MARKS replied:
It doesn't matter, you could take the gas and you could turn
it into chairs and sell the chairs; and you have gross value
just divided among the amount of gas going in. You recognize
that it's sold as an oil based product and higher value, but
in terms of administering the royalty, it's just divided among
the gas units going in.
TAPE 01-23, SIDE A
REPRESENTATIVE GREEN asked, regarding the conversion from gas to
liquid, whether Mr. Marks was using conversion estimates back in
the late 90s or current ones. He thought that ratio is becoming
more and more favorable.
MR. MARKS said he was using what Exxon's technology was in 1999.
CHAIRMAN TORGERSON thanked Mr. Marks for his testimony and
announced a short break.
2:43 p.m. - 3:00 p.m.- BREAK
[END OF TAPE]
[THE FOLLOWING TESTIMONY WAS NOT RECORDED]
DEPARTMENT OF REVENUE DEPUTY COMMISSIONER LARRY PERSILY said that
Cambridge Energy Research Associates (CERA) consultants would
present an update on their vision of current and short-term gas
prices in North America.
MR. ED SMALL, CERA, said that one of the most obvious things he
sees is overall economic weakness, but that they expect to see some
recovery in the mid part of next year and certainly in the second
half. Until then, the economic weakness translates into soft
demand. Demand is down in all sectors, especially steel and
chemical, but these are the areas in which they expect to see
recoveries in the third quarter. Demand losses next year due to a
return to normal hydrogenation will offset some of the return of
demand that was part of the fuel switching that occurred in the
first half of this year. He clarified, "In other words, we are
going to have offsetting factors next year to a certain extent…"
MR. SMALL told members that conservation has been a big factor,
especially in the residential, but also in the commercial sectors.
This is most apparent in the West where the local distribution
company programs for conservation and the higher prices have had a
big impact. He advised, "In fact, in the West we expect demand to
be down between 1.3 and 1.5 bcf/d through this winter and on
average next year."
MR. SMALL noted that CERA expects to see some demand strength in
the area of power generation. There is a question as to whether the
long-term demand for power generation has been impacted, which CERA
believes has happened. Growth has not been as strong as had been
anticipated. He stated, "Obviously, if you push demand down, it
takes longer to get back to that point and then to grow to a lower
point than where you had originally expected it to be."
MR. SMALL said CERA has seen roughly 55 gigawatts of new power
generation this year, almost all gas fired, and another 95
gigawatts of proposed and under-construction generation for 2002.
However, about 65 gigawatts will be built. In 2003, they are
showing a larger number of proposed and under-construction projects
of 110 gigawatts, but expect that number to get closer to 60.
Certainly, in 2002 and 2003, there is power generation that will
demand natural gas. The bigger question is how extensive will be
the operation of those facilities.
[END OF UNRECORDED TESTIMONY]
TAPE 01-24, SIDE A
3:05 p.m.
MR. SMALL informed members if the economy does not recover as
expected, then those facilities will not be operating at full
capacity and will not provide demand strength.
He said the overall picture for the Lower 48 for 2002 is demand
growth of about 1.6 bcf/d from both power and industrial
consumption. Again, most of the growth is expected to occur during
the last half of the year. In Canada, a similar demand decline is
expected to couple with a slower recovery. This is due to the fact
that the Canadian economy lags the Lower 48 and because there is
less power generation built there to provide the demand growth for
the up coming year.
MR. SMALL said that because the injection season in the U.S. has
ended with almost 3.1 trillion cubic feet (tcf) or close to the
absolute storage capacity of 3.2 tcf, storage in the Lower 48 will
be a big major factor this winter and through 2002. There is a net
inventory increase of 733 tcf this year over last. An obvious
impact of this increase is to reduce winter prices. It will take an
extremely cold winter to draw the gas reserves down a significant
amount or to the level they were at the end of last winter.
Additionally, they estimate that it will take a decrease of about 2
bcf/d to refill the storage reserves to the current level by the
end of the 2002 injection season.
The situation in Canada is similar to the Lower 48 with record high
storage levels in eastern Canada and near record levels in the
west. Here too, prices will be depressed.
Drilling in particular has been affected by the lower prices. They
estimate growth of about 400 million per day for 2001 and a decline
of about 500 million per day in 2002 due to the decline in drilling
they have seen over the last three months. Unless prices rise to a
sustainable $3.00 level, they do not believe drilling will recover
to the early 2001 level until later in 2002. However, the 500
million decline is more than offset by the increased storage levels
outlined earlier.
MR. SMALL explained that the Deep Water Gulf and the Rockies are
still growth areas while declines are being experienced in the more
mature fields, the newer fields that are more expensive from a
production perspective and the Shallow Shelf area in Mexico. Later
in 2002 there should be some recovery in drilling levels and will
provide a better picture of supply for 2003.
Canada differs in that drilling declines are typical in the fall
and increase in the winter for remote and exploratory locations.
Although it might be expected that remote and exploratory drilling
would decline with lower prices, all of the deep grades were fully
contracted last year for two and three year terms. Producers will
pay for the drilling rigs whether they use them or not, but the
odds are that they will use them. With the forgoing in mind, prices
should decline but not as much as in the Lower 48. Next summer
should not see a large drop because most of the drilling will be
shallow and more than economical at today's prices.
Because of the decline in Canadian demand and the lower storage
injection requirements for 2002, most of the anticipated 850-
million supply-growth will be exported to the Lower 48. It's
expected that the decline in Lower 48 supply will be more than
offset by Canadian growth next year.
MR. SMALL said the combination of demand decline and high storage
levels and increase in Canadian imports indicate continued soft
prices. They have declined from $3.25 to $2.75 and they expect them
to stay that way through the winter. With oil prices being lower
and gas prices close to $3.00, fuel switching becomes more
attractive. Therefore, oil will probably provide a ceiling for gas
prices through the winter.
Spring will bring even lower prices because there is a typical
softening of demand at that time and the economy probably won't
have recovered. This coupled with lower storage injection
requirements for next year will probably see prices pushed to $2.25
through early summer. If there is an economic recovery and the
typical summer demand for power generation occurs, then they expect
to see prices strengthen through the summer. A typical winter
season in conjunction with a Lower 48 supply decline and the
expected economic recovery should see prices back up to the $3.00
to $3.25 level for the winter period. This scenario should bring
back fairly robust drilling activity in 2003.
The price of Henry Hub is expected to average $2.71 in 2002 but for
the longer term there are adequate drivers to keep prices above
$2.00. Of equal importance, there are drivers that will keep prices
from staying much above $3.00 for the long term. Although there
will be some price volatility, they expect prices to range between
$2.50 and $3.50 between now and 2005.
CHAIRMAN TORGERSON said the last update outlined several
opportunities for Alaska gas to enter the market in 2008 and 2010.
He asked for the current projection for opportunities for Alaska
gas.
MR. SMALL thought the window of opportunity has shifted by about
one year. When demand decreases, it takes awhile to get back to
previous levels before you can grow beyond that point. Current
expectations are that there is probably opportunity for frontier
gas in the 2009 to 2010 time frame. Then in 2012 to 2014 there
should be need for additional gas. It's the same issue of where the
frontier gas will come from, but this is where the opportunity may
lie for Alaska and Arctic gas.
CHAIRMAN TORGERSON then wanted to know how they were plugging LNG
imports into their thought process.
MR. SMALL replied they were seeing the existing four LNG facilities
in the Lower 48 all come back on stream. Three are active now and
the last will come on stream next year. They expect those
facilities to expand in 2003 to 2005. They also expect to see
Greenfield LNG facilities built in the last half of this decade.
They do see that new facilities will be built, but don't know how
many.
Because of the September 11 attack, they are looking at the global
economy. The fragile nature of the Middle East could impact both
oil exports and LNG development from that region. This could have
an impact on the entire global LNG balance in the latter part of
this decade, but LNG is seen as being an integral part of new
supply in the Lower 48 in that time frame.
CHAIRMAN TORGERSON commented that he sees LNG imports rather than
other frontier gas as Alaska's biggest competition.
MR. SMALL responded that their definition of frontier gas is Artic
gas, which is both Alaska and Mackenzie, off shore East Canada and
LNG. Of those three, they see growth in LNG imports and offshore
East Canada. The questions now are what are the competitive forces
of LNG? Is Arctic gas able to compete and if so how will it
compete?
CHAIRMAN TORGERSON then asked whether CERA tracks the petro-
chemical industry.
MR. SMALL said it does.
CHAIRMAN TORGERSON asked if there is a market for polyethylene and
the anticipated delivery date.
MR. SMALL said there is always the opportunity for a market, but
here too the question of how the petro-chemical industry in Alaska
would compete globally must be addressed. Due to the cost of
transportation from the North Slope to tide water, Alaska would be
at a disadvantage because there are cheaper sources of stranded gas
globally. He was not sure about the window of opportunity, but
doubted it would be before the latter part of this decade.
CHAIRMAN TORGERSON then asked whether they were tracking the
fourteen countries that are starting GASPEC, which is patterned
after OPEC and would control world gas prices. He first heard of
this organization during his last trip to Washington D.C.
MR. SMALL replied that was outside his area of expertise, but that
he would have someone from CERA investigate. He added that the
success of such an organization would be more tenuous than OPEC
because it's a smaller part of a global market and transportation
costs would be more difficult to control. This said, it's not
beyond the realm of possibility.
CHAIRMAN TORGERSON said because energy security is such a large
issue, it's of greater concern that they are trying to do this than
the possibility that they will be successful.
REPRESENTATIVE DAVIES asked what major risk factors CERA is looking
at in terms of economic recovery in the next six months and if the
recovery doesn't occur, what price sensitivities CERA is
forecasting.
3:20 p.m.
MR. SMALL said consumer confidence and employment are major
signposts and the current stock market malaise figures heavily in
consumer confidence. In general, companies [are] starting to report
positive earnings even though they aren't the earnings anticipated
a year ago, which is a positive sign. Consumer confidence and
spending are critical in terms of bringing back demand in steel and
petrochemical sectors.
CERA does have a scenario that predicts recession lasting through
2004 and it shows prices of between $2.50 and $3.00 through that
period. In the context of Arctic gas, the window of opportunity is
pushed well beyond 2010, possibly to 2015.
CHAIRMAN TORGERSON thanked Mr. Small for his testimony and
announced the pipeline ownership study would be discussed next.
MR. LARRY PERSILY explained part of his testimony would duplicate
part of Roger Marks' testimony because risk is key in determining
whether the state should become an owner or financier of the
project. He then gave the following report:
Pursuant to your instructions in Senate Bill 158, the
Department of Revenue and its consultants have been working
for the past few months compiling a report for the legislature
on the merits of state or public ownership and/or financing of
a natural gas project. In addition to consulting with experts
on debt financing and project financing, we've interviewed
more than 30 individuals plus representatives from 10
companies in the oil and gas industry - not just the producers
but the large and not-so-large players in the pipeline
business. Our list of interviews also has included many
Alaskans involved in banking, the oil and gas industry,
legislators and business leaders.
Certainly, the Alaskans we interviewed all would like to see a
gas line built to create jobs in Alaska, to generate tax
revenues to pay for public services, and to promote the
economic activity that would come with such a large
construction project. Obviously, we don't need a study to
tell us that. What we're looking at are the risks to the
state - and the benefits - of becoming a member of any
partnership that builds and operates the line. And we're
looking at how - and what would happen - if the state wanted
to raise the hundreds of millions or billions of dollars
needed to buy into the project.
Here are some of the questions we're trying to answer:
What if we sign on as a partner and there are serious cost
overruns during construction? What if the partners are all
required to pay in more money to cover those overruns? Will
the state be able to come up with the money? It's always
possible that federal regulators - FERC - may not allow the
pipeline owners to recover 100% of the cost of any overruns.
Is it smart to commit to some possible unknown expense in the
future, given that the state already is running short of cash?
Even worse, what if some unforeseen event blocks or stalls
completion of the line? Granted, the risk is small judged by
the odds of it happening, but the risk does exist. We need to
consider that the Constitutional Budget Reserve Fund is at
$2.8 billion and falling. We're looking at less than $2.5
billion by the end of the fiscal year next June 30, and
perhaps as low as $1.5 billion one year later. The Permanent
Fund Earnings Reserve Account, which had $6.1 billion just a
couple of years ago, is around $2.7 billion this week after a
bad year in stocks while still continuing to pay full
dividends.
After the pipeline is built and the gas is flowing, there are
still risks to the owners of the line and/or the owners of the
gas. This is the cost of getting the gas to market, and
whether the market will be willing to pay that cost in full
year after year. Whereas the cost of moving North Slope oil to
market is about 25% of the sales price at the refinery, the
cost of moving gas to Chicago is closer to 80%. There just
isn't that much margin left after paying the transportation
tariff on a gas pipeline. A small swing in the market price
for gas could mean a loss for whoever is carrying the risk.
That's the central issue in all this. Who takes the risk that,
in any given year, the price for gas in Chicago will not be
sufficient to cover the tariff of moving it from Alaska to the
Midwest, plus the cost of production, taxes and a profit?
Generally, gas producers (the shippers) take this risk, but in
the case of the Alaska project, because of its size, we expect
there may be some risk sharing between the producers and
pipeline owners. Certainly, if the producers agree to take all
of the price risk, pipeline ownership could be a good
investment for the state, consistent with Permanent Fund
earnings on a risk-adjusted basis.
As I said, we expect that the three North Slope producers are
hesitant to take all the risk - the risk of construction cost
overruns if they build the pipeline and the larger risk that
some years the market will not pay enough to cover the $2 plus
pipeline tariff plus other costs. Even if you lose just a dime
on every thousand cubic of gas in a 4 billion cubic foot per
day line, that loss could total $400,000 a day, or almost $150
million over a full year.
Of course, pipeline companies would be happy to build the line
if producers agree to take all the risk, signing "ship-or-pay
contracts," committing to pay the pipeline companies a fixed
tariff regardless of the market price.
The decision whether to build the gasline, and who will
build it, will come down to a deal over who is willing to
share how much of the price risk.
Also thinking about risk, does it make sense for the state,
which is already heavily dependent on oil revenues, to take
a large investment in gas? Should we instead diversify from
the oil and gas sector in generating state revenues?
It's one thing for a corporation to take a risk that could
mean no dividends to shareholders if it goes sour one year.
It's another thing for a state to take a risk with providing
essential public services. Remember, we expect the Budget
Reserve to hit empty in 2005, and the Permanent Fund earnings
reserve has taken a major hit in the stock market.
Would the state be better off letting someone else take all
the risk, and we then would do what we do best - and that is
tax the profits?
Putting aside the risk issues, we next will have to answer the
questions: What can the state bring to table as a partner in
the project? Would state government involvement actually slow
down a commercial operation? Does the state gain anything
worthwhile for taking a share of the risk?
In our research and analysis, and our interviews with
producers and pipeline companies, here is what we've learned:
Project sponsors - be they gas producers or pipeline
companies - already have access to all the capital they
need if they decide to build the project. State
involvement just isn't needed for financing.
State investment doesn't do anything to lessen the
financial risks for the other partners, so they don't
gain anything from having us as a partner. The
marketplace dictates project risk, and the state has no
control over that.
Alaska already has a significant future income risk in
the energy sector. Why would people want to compound the
situation by making a large, discretionary investment in
energy? An executive said by investing in a project that
will not be cash-flow positive for a number of years, the
state is depriving its citizens of the present-income
value of its limited investment capital.
Although some may believe the state would gain a "seat at
the table" as a partner in the pipeline, we wouldn't
really gain any more information than we would be able to
get on our own - through the Federal Energy Regulatory
Commission, which would regulate pipeline tariffs, and
through the state's own regulatory agencies. We couldn't
use confidential, proprietary information from the table
against companies in tax cases, and we couldn't use the
information to out-maneuver our partners in gas marketing
opportunities.
As a partner, the state might face the political
temptation to meddle in the business operation.
As one pipeline company said, the state would need to
recognize that board discussions are open, frank and
confidential. Decisions would need to be made for the best
interest of the project, not necessarily the state.
Decisions of and debate of the joint venture board cannot be
shared publicly. This might not be compatible with state
ownership.
Another executive explained that a seat at the table is a fine
political concept, but the state's participation likely will
hurt the viability of the project. The decision-making
process of the state on the joint venture governing board
likely will be influenced by political, not business, concerns
and will be slow. Management of any joint venture is, by its
very nature, very difficult. A governmental entity will only
increase the complexity because governments are not accustomed
to making quick, unemotional decisions.
The state already can regulate much of the operations of the
line through right-of-way permits and regulatory oversight
functions.
Being a partner could put the state into a conflict of
interest situation. What would be more important to the state
- running the line at maximum profit, or following new,
perhaps costly environmental or safety or regulatory rules?
A final question is, should the state own a piece of a project
in a foreign country?
If the state decided to go ahead and take the risk as a
partner in the project, where would we get our share of the
cash to buy into the Gasline?
Under existing federal law, the state or any other public
entity could not issue tax-exempt debt except for a very small
portion of the project. Only those facilities available for
public use, such as a dock or highway or distribution hub
available for all users, would qualify under federal law for
tax-exempt financing. Everything else would be financed with
taxable bonds.
Federal law does allow the state to issue a limited amount of
tax-exempt debt for private-activity uses, but that currently
is set at $187 million a year, and is used in full by AHFC,
AIDEA, the student loan corporation and others.
Congress could change the tax laws as it has for other
projects, but without a change in federal law, tax-free bonds
do not appear to be possible for raising the state's share of
buying into the project. The same restriction likely would
apply to a port authority or other, similar public corporation
or agency.
Another issue is that we don't believe the state could issue
general obligation bonds for this project. State ownership in
the Gasline likely would fail to meet the required standard of
a capital improvement or public improvement.
But if we could issue GO bonds for our investment in the
pipeline - assuming the state wants to preserve its existing
AA credit rating - a conservative estimate of our debt
capacity would allow us to commit no more than 5% to 8% of our
general fund revenue stream to debt payments. That's been the
state's target for years, and it has served us well in
maintaining a good credit limit. At a limit of 8% of general
fund revenue, the state could issue somewhere around $200
million to $300 million in 10- or 15-year bonds over the next
six years. Those numbers are based on the state's current
fiscal situation, meaning the budget gap. If the state were
to adopt new revenue sources, be it taxes or using some
Permanent Fund earnings, we would have the capacity to issue
significantly more debt by the end of the decade.
But also keep in mind that any estimate of Alaska's bonding
capacity today does not yet account for bonds under
consideration, such as the new DEC seafood lab, deferred
maintenance on public buildings, schools and harbors. The
Gasline would have to compete with all those other needs for
GO debt.
The state or another public entity could issue revenue bonds,
pledging the future revenue from the Gasline to pay back the
debt. But there are some problems here, too.
One, if the state backed the revenue bonds with a moral
obligation, we'd have to use tax money or Permanent Fund
earnings if gas line revenues were insufficient in any given
year to cover debt service. If we sold the bolds based solely
on the gas line revenue - with no other assets or income at
risk - we'd probably have to pay much higher interest rates to
borrow that money. Much higher than what the producers or
pipeline companies would have to pay on their own debt.
Two, the state would be at risk if the gas flow or revenue
stream were disrupted. We would no longer have the revenue to
pay back the debt.
Three, even with pledging future gas line revenues, the state
still couldn't match the excellent credit rating and lower
interest rates that companies such as Exxon and BP could get.
For example, looking at taxable bonds, the difference between
Exxon's AAA rating and the state's AA rating - if we could
maintain that grade - would be $20 million in interest
payments in the first year on a $10 billion debt.
Four, we don't believe 100% project financing is feasible for
this project for any governmental entity. Regardless of what
the port authority is told by its lawyers and financial
advisers, our research indicates it is close to impossible to
obtain 100% debt financing for a project operated by a
government entity with no experience in such projects and with
just a single source of revenue to repay the debt. The answer
might be different if the producers were willing to absolutely
guarantee a high enough price for a high enough volume of gas
for a long enough period of time to pay back the debt, but if
they're going to take all the risk, why would they want to
work through the state or a port authority when they could
issue their own debt at a lower cost?
One other comment I want to make is that back in 1978 the
pipeline companies were encouraging state investment in the
project. Federal law back then prohibited oil and gas
producers from owning a pipeline, so that source of funding
was not available. The project was estimated to cost $20
billion or more, and that was more than the pipeline companies
could afford. Simply put, they needed the state. But the law
has changed and the producers can own the line. And the
financial strength of many of the companies involved has
grown. And the cost is much lower. No one really needs us
any more.
These are our preliminary findings and thoughts to date, and
could change as we continue with our work. Our final report
will be delivered in January, and we would be happy to give
you an update next month at your convenience.
3:39 p.m.
CHAIRMAN TORGERSON commented he hoped the department and its
consultants would be able to work through the concerns and list the
pros and cons for each of the points set forth.
There are additional suggestions in SB 158 that he would like to
have each addressed individually. One was the feasibility of
forming a public corporation and another was whether forming a port
authority is a good idea or not.
MR. PERSILY said they would address the other questions and list
the pros and cons for each and look for solutions to problems.
CHAIRMAN TORGERSON pointed out this is the third report of its kind
and none have recommended state ownership so it's doubtful that
there would be a change but some of their questions are different.
The comments about "seat at the table" were interesting but most of
the information is confidential not public. It is available to the
Department of Revenue of course but he has not been able to get
much tariff information on the oil pipeline due to the
confidentiality requirement. Tariff fluctuation of one half of a
percent could be a determinant. The shroud of confidentiality is
certainly not good for those making decisions because they must
simply accept figures given to them.
MR. PERSILY asked if this meant they needed to consider making as
small an investment as possible in order to gain access to that
confidential information.
CHAIRMAN TORGERSON said that has been suggested and perhaps the
information wouldn't be available even then but he would like to
know. He does look forward to state legislation in the upcoming
session to deal with some of the shroud.
3:45 p.m.
REPRESENTATIVE GREEN said there was a strong difference of opinion
on the tariffs on the oil pipeline and subsequent litigation. For a
more open policy there would need to be some degree of ownership.
If this is a good idea and the accessibility question is not
adequately addressed, then by owning 12.5 percent the State might
be able to allow access. On the con side, the State usually does
not compete with free enterprise.
MR. PERSILY said the law does not allow owners of a project to give
any preference to themselves for capacity. If the State wants
capacity, regardless of whether it's an owner or partner in the
pipeline, it would have to bid for capacity during open season like
everyone else. Then it is committed to filling that capacity just
like anyone else. Therefore, 12.5 percent ownership could not be
translated to 12.5 percent capacity of a regulated pipeline.
CHAIRMAN TORGERSON pointed out they have discussed owning a certain
capacity in a certain location if they wanted to do a large volume
user somewhere along the route.
MR. PERSILY replied that if the State was a contract carrier, it
would have to bid for capacity, it would not get it by owning 12.5
percent. You could own it without having capacity or you could pay
the capacity like any other shipper without owning it. It is his
understanding that for a contract carrier, capacity does not come
with ownership.
CHAIRMAN TORGERSON thought that was correct for going from Alaska
to Alberta but a question arises as capacity is added interstate.
REPRESENTATIVE DAVIES asked whether shared risk wasn't a valuable
element.
MR. PERSILY thought it might be but if there were so much risk that
it's desirable to dilute it, then the project probably wouldn't be
built. If they feel there is small enough risk to go ahead and
build then they might not want to share the wealth by taking in
other partners.
The State might bring more to the table without taking on risk by
working federal angles, such as accelerated depreciation. Because
producers have talked about fiscal certainty, the State could
certainly bring that to the table without being a partner
3:50 p.m.
Tape 01-24, SIDE B
REPRESENTATIVE DAVIES then asked whether the discount rate would be
affected to the extent that the State shares risk and whether an
investing company would be looking at this.
MR. PERSILY said that is a question for Roger Marks but the company
would be putting less of its own money at risk.
REPRESENTATIVE DAVIES said transportation costs are of concern with
the oil pipeline with companies that both transport and distribute.
Some suggest that if the State had some ownership, it could
insulate itself from that concern because it would benefit in the
same way. He asked if the State could shield itself if it had some
ownership and, if so, what percentage ownership would be optimal.
MR. PERSILY replied that if the State were absorbing 100 percent of
the transportation tariffs, the only way to offset that would be to
get 100 percent of the profit on the other end owning the entire
line. If the State took all the risk at the wellhead out but only
got 12.5 percent of the pipeline profits because it owned just 12.5
percent, it would come up short.
The gas line will be different than the oil line because it will be
regulated at a rate of return. No one foresees the problems that
were encountered with the oil pipeline in terms of cost shifting.
All Alaskans interviewed wanted the State to have a seat at the
table for the gas line because they thought there would be valuable
information available and they lacked that information on the oil
line and likely were cheated on the oil tariffs.
CHAIRMAN TORGERSON said there were also discussions about the State
owning the oil line 25 years ago and it wouldn't have been a bad
investment. He agreed that he wants a seat at the table but isn't
sure what he will learn. Older studies say that the state shouldn't
be an owner in the line, but that we should issue senior debt and
he hoped their report would look at that concept.
He remarked:
The barrier to the pipeline is how to manage risk -
whether it be fiscal [indisc.] from the state, whether it
be environmental laws or whatever it is. Back to what
Representative Davies said, if you have more folks to
share that risk, your exposure is less. Not that that
makes it a good deal, because I agree with you on that
statement, but at some point in time, the report said
that we should consider not owning the line, but helping
control the risk by issuing senior debt if they had cost
overruns.
CHAIRMAN TORGERSON said the oil pipeline started out costing $700
million and ended up being $10 billion. "They had a little bit of
cost overrun on the pipeline, so it was a very serious problem on
how to manage that cost overrun."
MR. PERSILY said that taking senior debt on this project might be
an attractive option for the state.
CHAIRMAN TORGERSON commented, "Of course, that was before Exxon was
making $5 billion per quarter. So, they can pay for this in one
year's profit."
MR. PERSILY said, "They owe us some of that."
CHAIRMAN TORGERSON said, "About all of that."
REPRESENTATIVE GREEN said the state has been historically getting
about 8 percent.
MR. PERSILY responded that 8.25 percent is the long-term assumption
for the Permanent Fund.
REPRESENTATIVE GREEN asked, "Since the state is obviously satisfied
with a much lower rate of return, would that make a difference in
making an investment in a portion of the pipeline?"
MR. PERSILY said it might, but the Permanent Fund Corporation's
8.25 percent long-term [indisc.] is much lower risk than the
assessed base they are working on. The state looks at how this
senior debt would compare to other debt the state is investing in
as part of its portfolio. He noted, "It might be very attractive."
CHAIRMAN TORGERSON asked if they decide to do a state ownership,
whether they are considering going through the Alaska Industrial
Development & Export Authority (AIDEA).
MR. PERSILY replied that they are looking at the difference in tax
laws. He explained:
If the state owned shares in a corporation, which we do
through current [indisc.] other investments, we don't
have to pay any federal income tax, but what if there
were limited liability company or a limited partnership
in those projects, would any of those projects flow to
the state? Would they put us in a taxable situation
that's any different if the state owns it or if we set up
a corporation similar to what we do with the Northern
Tobacco Securities Corporation, which is a dummy
corporation to shield the state if there's any default on
the tobacco bonds. But it really is a state corporation.
So, we'll be looking at those, too.
REPRESENTATIVE DAVIES asked if they were considering possible
conflict of interest. The Alaska Railroad has the citizens'
interest in environmental regulation handled by one state agency
and the citizens' interest in efficient economic operation by
another.
MR. PERSILY replied that was certainly possible, particularly after
all the spills on the Railroad last year. The conflict issue is not
an insurmountable one, such as federal laws that would prohibit tax
exempt financing. The conflict is more of a public policy question
to the legislature and to the governor. Is this such a concern that
you don't walk into it or do you walk into it knowing the issues,
knowing what you need to avoid with your eyes open?
CHAIRMAN TORGERSON thanked Mr. Persily for his testimony and asked
if he could have a draft of his responses ready by the end of
December or early January before he released the consultants.
MR. PERSILY agreed to do that.
4:02 p.m.
MR. BILL BRITT, Director, Pipeline Coordinator, reported that in
January, the Governor signed Administrative Order 187 that set up
the Gas Pipeline Office as a division of DNR and he assumed the
directorship of that. In July, he testified before the committee
and gave a summary of the proposals that were in play. None of that
has really changed since that time. He told members:
Right now we are working with Foothills and the producer
consortiums. With Foothills we are working on advancing
their right-of-way applications. With the producers, it
continues to be permitting for various aspects of their
feasibility studies. Just as an aside, I am frequently
asked about Yukon Pacific's conditional right-of-way and
that's being administered in the Joint Pipeline Office as
an existing lease. Should they choose to prove that up to
an unconditional lease or otherwise move that forward
aggressively, it might [indisc.] to hear, but for the
time being it's in the Joint Pipeline Office.
Again, by way of background, we were provided with
general funding by LBA in July. We signed reimbursement
memoranda of understanding with Foothills in July and
with the producers in August. Our funding is through the
ending of this calendar year and we are setting up
discussion right now with our three funding sources for
November and early December to discuss what happens in
the second half of this year.
Staff at this point consists of nine folks. Four
designated agencies have four additional people who have
been hired and will report this month. The three
remaining designated agencies are presently recruiting
[indisc.] and that recruiting in some instances is
proving to be fairly challenging. We have two assistant
attorney generals assigned to assist us. We have liaisons
from BLM and MMS. We are performing work with six other
divisions of DNR - Mining, Land and Water for land title
work, Land Records Information for land status work, the
Office of History and Archaeology for permitting support,
DGGS for research, Oil and Gas for technical assistance
and the State Pipeline Coordinator's Office continues to
provide us with administrative support. We're presently
in the Atwood Building. We'll be moving toward the end of
the year. The letter of interest has gone out, there have
been I think around a half dozen expressions of interest
and formal proposals will be received and evaluated next
week.
The work planning with Foothills is probably the most
intense effort that we have ongoing. In July, I received
from Foothills a reconstituted application, which was a
resubmittal of those aspects of the tons of papers we
received previously that Foothills considered to be
applicable to the existing project and applications.
We've met and identified high priority items. Some of
those are ongoing. A larger discussion is over the
process itself that will take place and those things are
now occurring about every other week in order to try and
pin this stuff down and keep it moving.
Doing ancillary stuff, we're working on our directory,
numbers and types of permits, not only for the state, but
for the feds and we will soon be moving to Canadians -
[indisc.] and private land owners as well. Critical
issues associated with each - we're flow charting out
these permits and beginning the process of synchronizing
them. We're outreaching federal government in attempting
to organize them since they are having difficulties in
organizing themselves. We've made contact with the EPA,
FAA, Coast Guard, Fish and Wildlife Service, DOT,
National Marine Fisheries, FERC, the FCC and the Corps of
Engineers and are getting information from each. I expect
Canada to be next. Probably toward the end of the year
and early next year I plan to travel to Calgary and
Ottawa and begin to make exactly the same sorts of
contacts.
The next step is to begin working with local governments,
native corporations, travel counsels. We need to do work
with the [indisc.] and the Railroad Corporation, both of
which we believe have land along the right-of-way. The
University may as well; that's now being checked.
Legislative session is coming up and I expect there to be
probably more than one bill relating to gas pipelines.
So, I'm expecting that to take some time. And in the next
year I hope to begin a reasonably serious outreach
program.
CHAIRMAN TORGERSON asked what was going on with YPC. He heard they
had downsized their office.
MR. BRITT replied that he was meeting tomorrow with the Right-of-
way Chief of the Joint Pipeline Office to get a briefing on that.
They have submitted a request for about 17 minor realignments of
their rights-of-way, which is now being processed. He hasn't heard
that this is setting off anything large, such as a large deep
evaluation over any serious reconsideration.
CHAIRMAN TORGERSON asked him to email anything he finds out about
that. He asked where they are at in the Foothills process.
MR. BRITT replied Foothills submitted a multi-volume collection of
exhibits that had been submitted previously that [Foothills]
thought was applicable to the questions that are asked in a right-
of-way lease application form. He is beginning the review.
CHAIRMAN TORGERSON asked what they were, stream crossing perhaps.
MR. BRITT replied that some of it is engineering work, a lot of it
is like an engineering design criteria handbook. The federal grant
of right-of-way under Stipulation 161 required in the neighborhood
of 30 separate plans for a whole variety of topics from resources
in Alaska to locations and excavations - a broad variety of topics.
Some of those plans were mothballed.
CHAIRMAN TORGERSON asked if they were reviewing the engineering
studies to see what needed to be repeated.
MR. BRITT replied that they need to critique them and determine
whether they are adequate and, if they are not, why. Perhaps they
are out of date or more information is needed or the world has
changed.
CHAIRMAN TORGERSON asked why they have more attorneys than
engineers.
MR. BRITT replied that attorneys are easier to find.
CHAIRMAN TORGERSON thanked Mr. Britt for his testimony and asked
him to keep the committee informed.
4:09 - 4:19 - BREAK
MR. JOHN LARSON, Geologist, U.S. Minerals Management Service (MMS),
said they have two off shore leases sales in Cook Inlet scheduled
for 2004 and 2006. Existing reserves in the Cook Inlet region have
been explored and are 2.564 TCF of gas, about a 12 year reserve if
gas in the area. There are about 6.6 years of oil reserves.
Further, exploration shows that the Cook Inlet Basin has
significant untapped natural gas resources.
Very few structures in the perspective OCS lease acreages involve
tertiary age formations that are so productive in the Upper Cook
Inlet. There are potential oil traps that can be seen on data, but
they don't have reservoir characteristics. Hypothetical coal bed
methane resources depend on the tertiary formations in Upper Cook
Inlet. He had projections done by the U.S. Geological survey that
he presented in a slide to the committee.
REPRESENTATIVE GREEN asked how they estimated their calculations.
MR. LARSON said they tried to use mean levels for their
calculations.
REPRESENTATIVE GREEN said that they seemed to be specific numbers,
but were still "guesstimates."
MR. LARSON concluded that the Cook Inlet basin has significant
untapped natural gas resources and the MMS is proposing two gas
lease sales in the area in 2004 and 2006.
CHAIRMAN TORGERSON asked what their responsibilities were for the
state and whether they just guess at the resources from oil and gas
numbers or do research.
MR. LARSON replied that the estimates on his slides were generated
by the U.S. Geological survey, which has done some research.
CHAIRMAN TORGERSON asked about Phillips' drilling.
MR. LARSON replied that their target depth as a vertical concern is
not that deep. "It's just that they're having to drill from on
shore a long distance off shore in order to get to it."
REPRESENTATIVE GREEN asked if the estimates were primary reservoirs
or oil associated.
MR. RANCE WALL, Regional Supervisor, MMS, replied that his
estimates were the oil and gas plays they had analyzed in the
northern part of the basin. It consisted of an interlude of a lot
of oil; those have very little associated gas with them. There is a
gas play in an interval above that which is nearly all gas. In that
case, one wouldn't think about using the gas for oil
pressurization.
REPRESENTATIVE GREEN asked if the gas would be available soon after
development.
MR. LARSON said that is correct and that "Some of the deeper oil
would have associated gas with it dissolved in the oil."
REPRESENTATIVE DAVIES said he thought the Inlet resources would be
all used up in 17 years.
CHAIRMAN TORGERSON asked how close their Cook Inlet estimates were
in the past.
MR. WALL responded that they started out being a lot bigger than
they are now.
CHAIRMAN TORGERSON asked if they were sure that the 10 holes
drilled in the OCS area were uneconomic so the chances of leasing
in Shelikof Straits are probably slim.
MR. WALL responded that is correct. He also said the five-year plan
is not official, it's just proposed.
REPRESENTATIVE DAVIES asked if there were any estimates that might
significantly alter the numbers.
MR. WALL responded that it depended on what decisions were made on
what to offer as they go through the NEPA process. One of the key
issues will be what the State wants them to do.
CHAIRMAN TORGERSON said the tri-borough commission (Kodiak,
[indisc.] and the Kenai Borough) met in the early '90s on how they
wanted to see development go forward. He thought that most of that
information would be the same, like restrictions in the fishing
areas and that kind of thing.
SENATOR OLSON asked if there were known reserves on federal lands.
MR. WALL responded that he thought there were, but they don't do
assessments for that area. He suspected there would be potential in
some areas if they were offered.
CHAIRMAN TORGERSON said he thought they did the work for BLM.
MR. WALL responded that they work with them.
CHAIRMAN TORGERSON asked if there were any further questions and
there were none. He adjourned the meeting at 4:45 p.m.
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